The present invention relates to subterranean treatment fluids. In particular, in some embodiments, the present invention relates to variable density subterranean treatment fluid compositions and methods for using such compositions. The present invention also relates to cementing in subterranean formations penetrated by well bores. In particular, in some embodiments, the present invention relates to cement compositions comprising variable pressure weighting material particles, and processes for making the compositions. The present invention also relates to variable density subterranean treatment fluids comprising variable density weighting materials and methods for preparing and for using such variable density subterranean treatment fluids.
A treatment fluid may be used in a subterranean formation in a variety of ways. For example, a fluid may be used to drill a borehole in a subterranean formation, to stimulate a well bore in a subterranean formation, and to clean up a well bore in a subterranean formation, as well as for numerous other purposes. The process of drilling a well typically requires the use of a treatment fluid referred to as a “drilling fluid.” During the drilling process, the drilling fluid passes down through the inside of the drill string, exits through the drill bit, and returns to the drill rig through the annulus between the drill string and well bore. The circulating drilling fluid, inter alia, lubricates the drill bit, carries drill cuttings to the surface, and balances the formation pressure exerted on the well bore. Additionally, a properly prepared drilling fluid enhances well drilling safety by preventing “kicks.” A kick is an uncontrolled flow of formation fluid into the well bore from the subterranean formation typically resulting from drilling into a zone of higher-than-expected or unanticipated pressure. Kicks may be both dangerous and very costly to drillers. Thus, drilling operators inherently wish to avoid or minimize kicks, or at least detect kicks as early as possible.
Drilling offshore in deep waters requires specially blended drilling fluids which must be carefully formulated to allow for, inter alia, the narrow range of pressure separating the pore pressure from the fracture gradient of the formation. As used herein, the term “pore pressure” refers to the pressure exerted on the borehole by fluids within the formation, while the term “fracture gradient” refers to that pressure that will fracture the formation. Such fracturing of the formation could result in flow of drilling fluids out of the borehole into the formation (commonly referred to as “lost circulation”), or possibly an uncontrolled blowout of the formation fluids, and in some cases, fluids and particulates. Accordingly, the weight of the drilling fluid preferably should be sufficient to balance the pore pressure (and thus provide the necessary protection against kicks) without inadvertently fracturing the sediment and rock around the drill bit.
The formulation of a drilling fluid satisfying these limitations is often complicated because the riser connecting the borehole to the drilling rig must often be quite long, particularly when drilling in deep water applications. As used herein, the term “riser” refers to a length of piping connecting the borehole to the drill ship or drilling rig, through which the drilling fluid is returned to the surface. The length of the riser column could be long, and thus the pressure exerted due to friction and hydrostatic forces could be considerable, even when at relatively shallow depths within the subterranean formation and even when using low density drilling fluids. Further complicating the formulation of the drilling fluid, at subsequent depths the hydrostatic and friction forces may be insufficient to prevent fluid influx from the formation.
Efforts to overcome this difficulty in drilling deep water wells have met with limited success. One proposed solution involves the installation of multiple strings of casing within the borehole to guard against inadvertent fracturing of the formation during the drilling process. This strategy is problematic because the installation of additional casing usually correspondingly reduces the usable diameter of the borehole. Furthermore, the installation of additional strings of casing may add greatly to the expense and complication of completing the well. Another option requires placement of pumps on the ocean floor, wherein drilling fluid exiting the well bore is diverted from the drilling riser annulus into the pumps. Subsequently, the pumps return the drilling fluid to the drill ship through additional pipes. Accordingly, in this method, the pumps remove the weight of the returning drilling fluid from the well bore. However, this method may not achieve desirable results because of the great expense involved in procuring and installing the system of risers and pumps. Another proposed option has been to reduce the density of the drilling fluid as it exits the well bore by injecting hollow rigid spheres into the drilling fluid to reduce the density of the drilling fluid. However, this method is problematic, inter alia, because of the cost and mechanical difficulty of injecting these spheres at the sea floor, and then separating them from the drilling fluid at the surface. Furthermore, the incompressible nature of these rigid spheres tends to cause them to crush at the pressures typically encountered in deepwater drilling; accordingly, such rigid spheres are typically unable to reduce the density of the drilling fluid while it travels upward toward the surface.
Analogous problems exist in other subterranean operations. For example, a fracturing or acidizing operation may involve additional expense in removing the spent fracturing or acidizing fluid from the well bore after the operation is conducted, due in part to the fixed-density nature of such fluids, which may necessitate additional manpower or pumping equipment to remove such fluid in a timely fashion. Other problems may exist in well cementing operations.
Well cementing is a process used in penetrating subterranean zones (also known as subterranean formations) to recover subterranean resources such as gas, oil, minerals, and water. In well cementing, a well bore is drilled while a drilling fluid is circulated through the well bore. The circulation of the drilling fluid is then terminated, and a string of pipe, e.g., casing, is run in the well bore. The drilling fluid in the well bore is conditioned by circulating it downwardly through the interior of the pipe and upwardly through the annulus, which is located between the exterior of the pipe and the walls of the well bore. Next, primary cementing is typically performed whereby a slurry of cement and water is placed in the annulus and permitted to set into a hard mass (i.e., sheath) to thereby attach the string of pipe to the walls of the well bore and seal the annulus.
Low density or lightweight cement compositions are commonly used in wells that extend through weak subterranean formations to reduce the hydrostatic pressure exerted by the cement column on the weak formation. Conventional lightweight cement compositions are made by adding more water to reduce the slurry density. Other materials such as bentonite, diatomaceous earth, and sodium metasilicate may be added to prevent the solids in the slurry from separating when the water is added. Unfortunately, this method has the drawback that the addition of more water increases the cure time and reduces the strength of the resulting cement.
Lightweight cement compositions containing hollow spheres have been developed as a better alternative to the cement compositions containing large quantities of water. The hollow spheres are typically cenospheres, glass hollow spheres, or ceramic hollow spheres. Cenospheres are hollow spheres primarily comprising silica (SiO2) and alumina (Al2O3) and are filled with gas. Cenospheres are a naturally occurring by-product of the burning process of a coal-fired power plant. Their size may vary from about 10 to 350 μm. These hollow spheres reduce the density of the cement composition such that less water is required to form the cement composition. The curing time of the cement composition is therefore reduced. Further, the resulting cement has superior mechanical properties as compared to cement formed by adding more water. For example, the tensile and compressive strengths of the cement are greater.
During the life of the well, the cement sheath is subjected to detrimental cyclical stresses due to pressure and temperature changes resulting from operations such as pressure testing, drilling, fracturing, cementing, and remedial operations. Conventional hollow spheres suffer from the drawback of being brittle and fragile and thus often cannot sustain those cyclical stresses. As a result, the cement sheath develops cracks and thus fails to provide zonal isolation for the life of the well. A need therefore exists to develop a less brittle cement having properties that would enable it to withstand pressure and temperature fluctuations for the life of the well. Embodiments of the present invention advantageously provide cement compositions that can withstand the cyclical stresses that occur during the life of the well.